Enclosed coiled tubing rig

CROSS REFERENCE TO RELATED APPLICATIONS

This application claims the benefit of U.S. Provisional Application No. 60/916,512, entitled “ENCLOSED COILED TUBING RIG,” filed May 7, 2007, the disclosure of which is hereby incorporated herein by reference.

BACKGROUND

Coiled tubing drilling offers the advantages of reduced time and costs associated with conventional drilling operations that utilize segmented pipe. These advantages include reduced pipe handling time, reduced pipe joint makeup time, and reduced leakage risks.

However, when coiled tubing drilling is utilized, conventional drilling may still be required to drill surface holes due to the lack of bit weight at the surface with coiled tubing drilling. A separate conventional drilling rig is then required to drill a surface hole, place surface casing, cement, and then drill to deeper depths. Thus, hybrid rigs exist that can perform both conventional drilling and coiled tubing drilling.

However, hybrid rigs are often utilized in extremely cold environments, such as Alaska. These rigs typically feature a fixed coiled tubing reel location, which is cumbersome and difficult to position and operate, particularly in extremely cold environments. Moreover, the entire coiled tubing unit (e.g., reel and injector) is exposed to the cold environment, and can be subject to freeze-up or other weather-induced failure.

BRIEF DESCRIPTION OF THE DRAWINGS

The present disclosure is best understood from the following detailed description when read with the accompanying figures. It is emphasized that, in accordance with the standard practice in the industry, various features are not drawn to scale. In fact, the dimensions of the various features may be arbitrarily increased or reduced for clarity of discussion.

<figref idrefs="DRAWINGS">FIG. 1</figref> is a side view of a coiled tubing rig according to one or more aspects of the present disclosure.

<figref idrefs="DRAWINGS">FIG. 2</figref> is a sectional plan view of the apparatus shown in <figref idrefs="DRAWINGS">FIG. 1</figref>.

<figref idrefs="DRAWINGS">FIG. 3</figref> is another sectional plan view of the apparatus shown in <figref idrefs="DRAWINGS">FIG. 1</figref>.

<figref idrefs="DRAWINGS">FIG. 4</figref> is another sectional plan view of the apparatus shown in <figref idrefs="DRAWINGS">FIG. 1</figref>.

<figref idrefs="DRAWINGS">FIG. 5</figref> is a side view of the apparatus shown in <figref idrefs="DRAWINGS">FIG. 1</figref> in a pressure deployment lubricator handling configuration according to one or more aspects of the present disclosure.

<figref idrefs="DRAWINGS">FIG. 6</figref> is a side view of the apparatus shown in <figref idrefs="DRAWINGS">FIG. 1</figref> in a drilling configuration according to one or more aspects of the present disclosure.

<figref idrefs="DRAWINGS">FIG. 7</figref> is a flow-chart diagram of at least a portion of a method according to one or more aspects of the present disclosure.

DETAILED DESCRIPTION

It is to be understood that the following disclosure provides many different embodiments, or examples, for implementing different features of various embodiments. Specific examples of components and arrangements are described below to simplify the present disclosure. These are, of course, merely examples and are not intended to be limiting. In addition, the present disclosure may repeat reference numerals and/or letters in the various examples. This repetition is for the purpose of simplicity and clarity and does not in itself dictate a relationship between the various embodiments and/or configurations discussed. Moreover, the formation of a first feature over or on a second feature in the description that follows may include embodiments in which the first and second features are formed in direct contact, and may also include embodiments in which additional features may be formed interposing the first and second features, such that the first and second features may not be in direct contact.

<figref idrefs="DRAWINGS">FIG. 1</figref> is a partial sectional view of a coiled tubing rig <b>100</b> in a traveling configuration according to one or more aspects of the present disclosure. The coiled tubing rig <b>100</b> is fully enclosed within an exterior wall <b>104</b>. Being fully enclosed within the exterior wall <b>104</b> allows drilling equipment and other components of the coiled tubing rig <b>100</b> to more easily be maintained at an adequate temperature and, thereby, eliminate freeze up. For example, the exterior wall <b>104</b> shields the interior of the rig <b>100</b> from wind and other harsh elements of cold environments, and may also help to prevent the escape of any thermal energy generated inside the interior of the rig <b>100</b>. Alternatively, the exterior wall <b>104</b> may shield the interior of the rig <b>100</b> from other weather elements in environments other than cold environments, such as by protecting the interior of the rig <b>100</b> from sand or other airborne debris which may exist in warmer environments (e.g., the desert).

<figref idrefs="DRAWINGS">FIG. 2</figref> is a sectional plan view of a first level <b>101</b><i>a </i>of the coiled tubing rig <b>100</b> shown in <figref idrefs="DRAWINGS">FIG. 1</figref>. Referring to <figref idrefs="DRAWINGS">FIGS. 1 and 2</figref>, collectively, the coiled tubing rig <b>100</b> is designed to be transported by a truck <b>106</b> and is constructed as a mobile trailer having, for example, bottom structural framework that includes wheels <b>110</b> that support the coiled tubing rig <b>100</b> during travel. The first level <b>101</b><i>a </i>includes an engine room <b>112</b> and a motor control center <b>114</b> positioned in front of the wheels <b>110</b>, as well as one or more hydraulic units <b>116</b> and air compressors <b>118</b>.

The engine room <b>112</b> houses one or more motor/generator sets <b>202</b>. Each motor/generator set <b>202</b> may be or comprise, for example, a Caterpillar C18 motor/generator set rated at 735 BHP at 1200 rpm. The motor control center <b>114</b> may include variable frequency drive technology to provide variable AC power to the drilling and support machinery. The motor control center <b>114</b> may also include the ability to utilize incoming electrical power, such as incoming 13.8 kV power, when available. Radiators <b>204</b> and a day tank <b>206</b> may also be housed within the first level <b>101</b><i>a</i>, and may be positioned forward of the motor control center <b>114</b>, as shown in <figref idrefs="DRAWINGS">FIG. 2</figref>.

<figref idrefs="DRAWINGS">FIG. 3</figref> is a sectional plan view of a second level <b>101</b><i>b </i>of the coiled tubing rig <b>100</b> shown in <figref idrefs="DRAWINGS">FIGS. 1 and 2</figref>. Referring to <figref idrefs="DRAWINGS">FIGS. 1 and 3</figref>, collectively, the coiled tubing rig <b>100</b> includes one or more pipe sheds <b>120</b>, such as may be located above the engine room <b>112</b>. For example, one pipe shed <b>120</b> may include two independent, hydraulically controlled pipe tubs, such as a first tub <b>120</b><i>a </i>capable of housing <b>100</b> joints of 3½″ pipe and a second tub <b>120</b><i>b </i>capable of housing <b>100</b> joints of 2⅜″ pipe. The pipe shed <b>120</b> may have a capacity of 8,000 lbs of 20″ maximum diameter pipe, and may accommodate tubulars with a 45′-0″ maximum length, although other configurations are also within the scope of the present disclosure. The coiled tubing rig <b>100</b> also includes a pressure deployment lubricator (“PDL”) <b>121</b> and a pipe handler system <b>122</b>, such as, for example, a Columbia Pipe Handler System, although these are depicted by dashed lines in <figref idrefs="DRAWINGS">FIG. 3</figref> as they are not always positioned proximate to the second level <b>101</b><i>b </i>of the rig <b>100</b>.

The pipe shed <b>120</b> may also include or be configured for operation in conjunction with one or more bottom hole assembly racks and rollers, although other configurations are also within the scope of the present disclosure. The pipe shed <b>120</b> may also include or be configured for operation in conjunction with one or more overhead cranes. In an exemplary embodiment, the pipe shed <b>120</b> contains two independent 5-ton overhead cranes, along with a set of Lil Jerk tongs for assistance in making-up/breaking-out bottom hole assembly (BHA) components, although other configurations are also within the scope of the present disclosure.

During operation, the exterior wall <b>104</b> surrounds the pipe housed within the pipe shed <b>120</b>, and also surrounds the PDL <b>121</b> and pipe machine <b>122</b>. Consequently, the pipe in the pipe shed <b>120</b>, the PDL <b>121</b> and the pipe machine <b>122</b> are protected from the external environment. Thus, for example, a minimum temperature of the pipe in the pipe shed <b>120</b>, the PDL <b>121</b> and the pipe machine <b>122</b> may be maintained despite high winds and/or freezing temperatures outside of the exterior wall <b>104</b>.

The coiled tubing rig <b>100</b> may also include a retractable corridor <b>123</b> extending from one side for providing a temporary or permanent walkway to an adjacent mud pit, rig, facility and/or other structure. One or more ladders or stairways <b>124</b> may also provide human access between the levels of the rig <b>100</b>.

The exterior wall <b>104</b> of the rig <b>100</b> may be configured to further enclose a blow out preventer (BOP) <b>140</b> (or more than one BOPs, hereafter collectively referred to as the BOP <b>140</b>). For example, a portion <b>104</b><i>a </i>of the exterior wall <b>104</b> may be configured to enclose the BOP <b>140</b> and, as such, may be substantially centered around the wellbore <b>103</b>. This portion <b>104</b><i>a </i>of the exterior wall <b>104</b> may be smaller in width W and/or other dimensions relative to the remainder of the exterior wall <b>104</b>, such that the smaller enclosed volume around the BOP <b>140</b> may further aid in maintaining the BOP <b>140</b> above a predetermined temperature. In an exemplary embodiment, the predetermined temperature may be about 40° F., although other temperatures above 32° F. are also within the scope of the present disclosure. Nonetheless, the portion <b>104</b><i>a </i>of exterior wall <b>104</b> surrounding the BOP <b>140</b> may also have substantially the same width as the remainder of the exterior wall <b>104</b>, or may be otherwise configured within the scope of the present disclosure.

The BOP <b>140</b> may extend from a lower point proximate the opening of the wellbore <b>103</b> and upwards beyond the first and second levels <b>101</b><i>a</i>, <b>101</b><i>b </i>of the rig <b>100</b>. Thus, while the BOP <b>140</b> is not shown in <figref idrefs="DRAWINGS">FIG. 3</figref>, its position relative to other components of the rig <b>100</b> it is understood, at least in part by its depiction in <figref idrefs="DRAWINGS">FIG. 1</figref>. Nonetheless, it should also be understood that the BOP <b>140</b> is configured to be laterally positioned proximate to the opening of the wellbore <b>103</b> by positioning of the rig <b>100</b>, as depicted in <figref idrefs="DRAWINGS">FIG. 1</figref>. However, the rig <b>100</b> may include positioning means to align the BOP <b>140</b> with the wellbore <b>103</b> other than with (or in addition to) positioning of the rig <b>100</b>.

<figref idrefs="DRAWINGS">FIG. 4</figref> is a sectional plan view of a third level <b>101</b><i>c </i>of the coiled tubing rig <b>100</b> shown in <figref idrefs="DRAWINGS">FIGS. 1-3</figref>. Referring to <figref idrefs="DRAWINGS">FIGS. 1 and 4</figref>, collectively, the coiled tubing rig <b>100</b> includes a coiled tubing reel drive system that travels on structural rails <b>128</b> which extend the substantial length of the coiled tubing rig <b>100</b>. In an exemplary embodiment, the coiled tubing reel drive system is or comprises a coiled tubing reel drive system manufactured by Foremost Industries. The coiled tubing reel drive system may include a coiled tubing reel <b>134</b> and, for example, a 50 ton lift system <b>135</b> for raising and lowering the coiled tubing reel. In <figref idrefs="DRAWINGS">FIG. 1</figref>, the lift system <b>135</b> is shown in a traveling configuration in which it is collapsed for storage within the exterior wall <b>104</b>. In <figref idrefs="DRAWINGS">FIG. 4</figref>, the lift system <b>135</b> is not shown because, in its stored or collapsed configuration, it is positioned above the section cut of <figref idrefs="DRAWINGS">FIG. 4</figref>. However, <figref idrefs="DRAWINGS">FIG. 4</figref> does depict that the pipe machine <b>122</b> and coiled tubing reel <b>134</b> are mutually aligned or centered, and that both may be centered relative to the rig <b>100</b> and/or the wellbore <b>103</b>.

As best shown in <figref idrefs="DRAWINGS">FIG. 1</figref>, the coiled tubing rig <b>100</b> also includes a coiled tubing injector drive cart <b>136</b> which also travels on the structural rails <b>128</b>. The coiled tubing injector drive cart <b>136</b> holds a coiled tubing injector <b>138</b>, such as, for example, a coiled tubing injector M<b>100</b> made by Stewart and Stevenson. The coiled tubing reel drive system and the coiled tubing injector drive cart <b>136</b> may be linked together for concurrent movement along the structural rails <b>128</b>, or they may be driven independently on the rails <b>128</b>. In an exemplary embodiment, the coiled tubing reel drive system and the coiled tubing injector drive cart <b>136</b> are manufactured as an integral unit and, thus, travel along the structural rails <b>128</b> together. Whether formed as an integral unit or as discrete components that are mechanically coupled together, the integrated handling system configured to position the coiled tubing reel drive system and the coiled tubing injector drive cart <b>136</b> together as a single unit allows the weight of the coiled tubing rig <b>100</b> to be balanced forward and aft for moving the coiled tubing rig <b>100</b>. The handling system also provides the proper distance between the coiled tubing injector <b>138</b> and the coiled tubing reel <b>134</b>, such as for spooling purposes.

As shown in <figref idrefs="DRAWINGS">FIG. 4</figref>, the coiled tubing rig <b>100</b> may include an additional retractable corridor <b>123</b> extending from one side for providing a temporary or permanent walkway to an adjacent mud pit, rig, facility and/or other structure. One or more ladders or stairways <b>124</b> may also provide human access between the levels of the rig <b>100</b>.

The rig <b>100</b> may also include a driller's cabin <b>404</b> and/or an ODS toolhouse/choke manifold <b>402</b>. In an exemplary embodiment, the dimensions of the driller's cabin <b>404</b> may be about 10′ W×23′ L×10′ H, although other sizes are also within the scope of the present disclosure. Machinery automation and low noise levels within the driller's cabin <b>404</b> may be such that operators are provided with a calm environment in which to work. The coiled tubing injector <b>138</b> push/pull and block hoisting/lowering may be controlled by a joystick or other human-machine interface from within the cabin <b>404</b>.

Quality of work and important decision making are improved in this atmosphere. The console and other control panels within the driller's cabin <b>404</b> are configured to allow personnel to complete regular shifts without stress or strain, despite the harsh environment outside of the cabin <b>404</b>. Operational controls and parameters, such as hook load, block height, speed and rate of penetration (ROP), as well as status and alarms, may be accessed via touch screens connected to the drilling control network. The control system may include several features configured to help the driller optimize efficiency and safety of operation, including: coiled tubing tension minimum and maximum set points; coiled tubing stress analysis and life management; managed pressure choke control; block position limits (crown saver and floor saver); block speed limits (safety limits, swab, surge and casing speed); driller's set points (stopping positions); over-pull limits and snubbing limits; drilling and tripping process screens; pit volume, flow, and pit valve control. The electronic drilling control algorithms help drillers significantly reduce drilling costs and improve rig safety. Superior drilling performance may be achieved by precisely monitoring or maintaining up to four parameters simultaneously: weight on bit (WOB), ROP, drilling torque and delta-P (differential down-hole motor pressure). These design features may provide consistent, steady-state control at the drill bit, which may result in longer bit life, optimum bit performance, reduced bit usage and reduced bit trips. This system may also help improve directional drilling control and accuracy.

The rig <b>100</b> may further comprise a top drive, such as, for example, a 150 Ton Foremost Model F-150T AC Top Drive. The rig <b>100</b> may also include drawworks, such as, for example, a Pacific Rim Commander 350, as well as a pedestal configured to support the mast of the list system <b>135</b>. One or more of these components may be mounted at the rear of the rig <b>100</b>. A rotary table may be used either in lieu of, or in conjunction with, the top drive. The coiled tubing rig <b>100</b> is configured for drilling with coiled tubing or with a top-drive and mast configuration. The mast may be positioned horizontally over the top of the coiled tubing reel <b>134</b> during traveling, as in the configuration shown in <figref idrefs="DRAWINGS">FIG. 1</figref>.

Referring to <figref idrefs="DRAWINGS">FIG. 5</figref>, the coiled tubing rig <b>100</b> is shown in a lubricator handling configuration. In the lubricator handling configuration, roof doors <b>502</b> are opened and the mast <b>148</b> of the lift system <b>135</b> is raised to a vertical position. After opening, the roof doors <b>502</b> may be lowered for increased strength and rigidity during high winds. The coiled tubing injector drive cart <b>136</b> and coiled tubing reel drive system, including the reel <b>134</b>, are moved to a forward position on the main structural rails <b>128</b>.

The mast <b>148</b> includes a boom arm <b>150</b> located at the crown of the mast. A cable <b>154</b> extends from the boom arm <b>150</b> and, in the embodiment shown in <figref idrefs="DRAWINGS">FIG. 5</figref>, is connected to and supports the weight of the PDL <b>121</b>. In operation, the pipe shed <b>120</b> is configured to allow for BHA components to be made-up, electrically tested for continuity, and then inserted into the PDL <b>121</b>. The PDL <b>121</b> and BHA are then raised into a substantially vertical position by the mast <b>148</b>, as shown in <figref idrefs="DRAWINGS">FIG. 5</figref>. The PDL <b>121</b> may be raised to a clear height of 95′ through the use of the boom arm <b>150</b> and in conjunction with tilting the mast <b>148</b> five degrees towards the rear of the coiled tubing drilling rig <b>100</b>. The BHA may then be deployed into the wellbore <b>103</b> following conventional procedures. Following deployment of the BHA, the PDL <b>121</b> may be racked back to the mast <b>148</b> or otherwise stored.

Referring to <figref idrefs="DRAWINGS">FIG. 6</figref>, the coiled tubing rig <b>100</b> is shown in a drilling configuration. The coiled tubing injector drive cart <b>136</b> and coiled tubing reel drive system are moved to a rearward position on the main structural rails <b>128</b>. The coiled tubing injector <b>138</b> may be raised for mounting to the PDL <b>121</b>, while maintaining the necessary coiled tubing tension back to the coiled tubing reel <b>134</b>. For demonstration purposes, the mast <b>148</b> is depicted in <figref idrefs="DRAWINGS">FIG. 6</figref> in both the PDL handling configuration of <figref idrefs="DRAWINGS">FIG. 5</figref> and in the drilling configuration of <figref idrefs="DRAWINGS">FIG. 6</figref>. Of course, it is understood that the rig <b>100</b> does not necessarily include two separate masts <b>148</b>, as shown in <figref idrefs="DRAWINGS">FIG. 6</figref>.

During operation, the exterior wall <b>104</b> surrounds a portion of coiled tubing <b>134</b><i>a </i>that extends from the coiled tubing reel <b>134</b> to the coiled tubing injector <b>138</b>. Consequently, this portion of the coiled tubing <b>134</b><i>a</i>, as well as the coiled tubing reel <b>134</b> and injector <b>138</b>, are protected from the environment. Thus, for example, a minimum temperature of the coiled tubing <b>134</b><i>a</i>, reel <b>145</b> and injector <b>138</b> may be maintained despite high winds and/or freezing temperatures outside of the exterior wall <b>104</b>.

In an exemplary embodiment, the enclosed coiled tubing rig <b>100</b> shown in <figref idrefs="DRAWINGS">FIGS. 1-6</figref> may further comprise one or more heaters coupled to the structure of the trailer internal to the enclosure <b>104</b>. For example, the rig <b>100</b> may include two 2.5MM BTU heaters each operable at 20 gal/hr. The heater(s) may be positioned on any of the levels <b>101</b><i>a</i>, <b>101</b><i>b</i>, <b>101</b><i>c </i>of the rig <b>100</b>, or elsewhere within the rig <b>100</b>. In one embodiment, each level of the rig <b>100</b> includes at least one heater. The one or more heaters may be configured to maintain the internal temperature of the rig <b>100</b>, internal to the exterior wall <b>104</b>, at or above a minimum temperature. For example, the minimum temperature may be about 40° F., although other temperatures are also within the scope of the present disclosure.

<figref idrefs="DRAWINGS">FIG. 7</figref> is a flow-chart diagram of at least a portion of an operational method <b>700</b> for the coiled tubing rig <b>100</b> shown in <figref idrefs="DRAWINGS">FIGS. 1-6</figref> according to one or more aspects of the present disclosure. Referring to <figref idrefs="DRAWINGS">FIG. 7</figref>, with continued reference to <figref idrefs="DRAWINGS">FIGS. 1-6</figref>, the method <b>700</b> includes a step <b>705</b> in which the coiled tubing rig <b>100</b> is transported to the well-site. For example,

In a subsequent step <b>710</b>, the mast <b>148</b> is configured. For example, the roof doors <b>502</b> may be opened and the mast <b>148</b> may be raised and possibly tilted back (e.g., away from the coiled tubing reel <b>134</b>, perhaps by about five degrees) in preparation for raising the PDL <b>121</b>. A bottom hole assembly (BHA) may then be inserted into the PDL <b>121</b> in a step <b>715</b>. Thereafter, the PDL <b>121</b> may be picked up from the pipe shed <b>120</b> using the mast <b>148</b>, and the PDL <b>121</b> may be coupled to the BOP <b>140</b> in a step <b>720</b>.

The BHA may then be deployed into the wellbore in a step <b>725</b>. In a subsequent step <b>730</b>, the PDL <b>121</b> stowed. For example, the PDL <b>121</b> may be racked back to the mast <b>148</b> in a vertical storage position. Thereafter, in a step <b>735</b>, the coiled tubing injector <b>138</b> and the coiled tubing injector drive cart <b>136</b> may be translated from their forward position (or elsewhere they may remain positioned during handling of the PDL <b>121</b>) and positioned over the wellbore center. The coiled tubing may then be coupled to the BHA in a step <b>740</b>. In a subsequent step <b>745</b>, the drill string is lowered in the well bore (“trip-in”), drilling operations are undertaken, and the drill string is brought out of the well bore (trip-out”) with the BHA brought to the top of the well bore. The coiled tubing and BHA may then be decoupled in a step <b>750</b>, and the coiled tubing injector <b>138</b> and the coiled tubing injector drive cart <b>136</b> may be translated away from the well center in a subsequent step <b>755</b>.

A decisional step <b>760</b> is then performed to determine whether a new coiled tubing reel <b>134</b> is needed. If a new reel <b>134</b> is needed, a step <b>765</b> is performed, during which the existing reel may be translated by the coiled tubing reel drive system <b>132</b> to a forward position on the main structural rails <b>128</b>, where the lift system may lower the used coiled tubing reel for replacement with a new coil tubing reel. The coiled tubing reel drive system <b>132</b> may then return the coiled tubing reel <b>134</b> to a position where the coiled tubing may be coupled to the BHA as step <b>740</b> and subsequent steps are repeated.

If a new coiled tubing reel is not needed, as determined during decisional step <b>760</b>, a decisional step <b>770</b> may be performed to determine whether a new BHA may be needed, such as in response to dulling of the drill bit. If a new BHA is needed, a step <b>775</b> is performed, during which the PDL <b>121</b> may be repositioned to the BOP <b>140</b> from its racked position on the mast <b>148</b>. In a subsequent step <b>780</b>, the BHA may be pulled into the PDL <b>121</b> and the PDL <b>121</b> may be released from the BOP <b>140</b>. Thereafter, in a step <b>785</b>, the PDL <b>121</b> containing the used BHA may then be lowered into the pipe shed <b>120</b> where a new BHA may be inserted into the PDL, and the PDL <b>121</b> with the new BHA may be picked up from the pipe shed <b>120</b> by the mast <b>148</b> and coupled to the BOP <b>140</b>. The method <b>700</b> may then proceed to repeat step <b>725</b> and subsequent steps.

If a new BHA is not needed, as determined during decisional step <b>770</b>, a step <b>790</b> may be performed, during which the well may be completed. The coiled tubing rig <b>100</b> may then be returned to its traveling configuration <b>102</b> in a subsequent step <b>792</b> by, for example, returning the PDL <b>121</b> containing the BHA to the pipe shed <b>120</b>, lowering the mast <b>148</b>, closing the roof doors <b>502</b>, and returning the coiled tubing injector drive cart <b>136</b>, coiled tubing injector <b>138</b> and the coiled tubing reel drive system <b>132</b> to their traveling positions. In an optional step <b>794</b>, the coiled tubing rig <b>100</b> may be transported to another well site.

In view of the above and the figures, it should be apparent to those skilled in the art that the present disclosure introduces an apparatus comprising a mobile trailer, a coiled tubing unit coupled to the mobile trailer, and an enclosure surrounding the coiled tubing unit. The coiled tubing unit may comprise a coiled tubing reel and a coiled tubing injector, wherein the reel and the injector are positionally fixed relative to one another and collectively move relative to the mobile trailer as an integral unit. At least one of coiled tubing deployment, coiled tubing retraction, and lateral translation of the coiled tubing unit relative to the trailer may be configured to be substantially automated. The apparatus may further comprise a track extending at least a portion of the length of the trailer, wherein the coiled tubing unit is configured to translate along the track laterally relative to the trailer. The enclosure may surround a portion of coiled tubing that extends from the coiled tubing reel to the coiled tubing injector. The apparatus may further comprise a pipe shed coupled to the trailer, wherein the pipe shed is enclosed by the enclosure and is configured to receive a plurality of pipe segments. The apparatus may further comprise a lifting system configured to transfer the pipe segments from the pipe shed. The apparatus may further comprise a heater coupled to the trailer internal to the enclosure, such as two 2.5MM BTU heaters each operable at 20 gal/hr. The apparatus may further comprise a pressure deployment lubricator detachably coupled to the trailer. The pressure deployment lubricator may be configured to receive a bottom hole assembly. The apparatus may further comprise a blow-out preventer coupled to the trailer.

The present disclosure also introduces a method comprising, at least in one embodiment, one or more of the following steps: transporting an apparatus as described in the previous paragraph to a drilling site; opening doors in a roof section of the enclosure; rotating a mast of the apparatus between a mast-stored position and a mast-deployed position; translating the coiled tubing unit to a PDL-accessible position; coupling the BHA to the PDL; moving the PDL between a PDL-stored position and a PDL-deployed position; installing the PDL into a wellbore through a blow out preventer component of the apparatus; decoupling the PDL from the BHA; moving the PDL away from the PDL-deployed position; translating the coiled tubing unit to a coiled-tubing-unit-operating position; extending coiled tubing from the coiled tubing unit; coupling the coiled tubing to the BHA; and operating the BHA to extend the wellbore while suspending the BHA within the wellbore from the coiled tubing. Such method may also include one or more of these steps in a sequence other than as listed above.

The present disclosure also provides a method of extending a wellbore in a subterranean formation, comprising translating a coiled tubing unit within an enclosure to a first position and then inserting a bottom hole assembly (BHA) into the wellbore using a lifting system while the coiled tubing unit is in the first position, wherein the coiled tubing unit and at least a portion of the lifting system are enclosed within the enclosure, and wherein the coiled tubing unit comprises coiled tubing, a coiled tubing reel and a coiled tubing injector. The method further comprises translating the coiled tubing unit within the enclosure to a second position and then coupling the coiled tubing to the BHA and operating the BHA to extend the wellbore while the coiled tubing unit is in the second position. Using the lifting system may comprise opening doors in a roof section of the enclosure and rotating a mast of the lifting system through the opened enclosure doors. Inserting the BHA into the wellbore may comprise moving a pressure deployment lubricator (PDL) between a PDL-stored position and a PDL-deployed position and coupling the PDL with the wellbore through a blow out preventer (BOP), wherein the PDL and the BOP are each enclosed within the enclosure. The coiled tubing reel and the coiled tubing injector may be positionally fixed relative to one another and collectively move as an integral unit. The method may further comprise maintaining a temperature internal to the enclosure above a predetermined temperature by operating at least one heater enclosed by the enclosure. The coiled tubing unit and the enclosure may be coupled to a trailer, and the method may further comprise positioning the trailer relative to the wellbore.

The foregoing outlines features of several embodiments so that those skilled in the art may better understand the aspects of the present disclosure. Those skilled in the art should appreciate that they may readily use the present disclosure as a basis for designing or modifying other processes and structures for carrying out the same purposes and/or achieving the same advantages of the embodiments introduced herein. Those skilled in the art should also realize that such equivalent constructions do not depart from the spirit and scope of the present disclosure, and that they may make various changes, substitutions and alterations herein without departing from the spirit and scope of the present disclosure.